Downhole fluid analysis is an important and efficient investigative technique typically used to ascertain characteristics and nature of geological formations having hydrocarbon deposits. In this, typical oilfield exploration and development includes downhole fluid analysis for determining petrophysical, mineralogical, and fluid properties of hydrocarbon reservoirs. Fluid characterization is integral to an accurate evaluation of the economic viability of a hydrocarbon reservoir formation.
Typically, a complex mixture of fluids, such as oil, gas, and water, is found downhole in reservoir formations. The downhole fluids, which are also referred to as formation fluids, have characteristics, including pressure, temperature, volume, among other fluid properties, that determine phase behavior of the various constituent elements of the fluids. In order to evaluate underground formations surrounding a borehole, it is often desirable to obtain samples of formation fluids in the borehole for purposes of characterizing the fluids, including composition analysis, fluid properties and phase behavior. Wireline formation testing tools are disclosed, for example, in U.S. Pat. Nos. 3,780,575 and 3,859,851, and the Reservoir Formation Tester (RET) and Modular Formation Dynamics Tester (MDT) of Schlumberger are examples of sampling tools for extracting samples of formation fluids from a borehole for surface analysis.
Formation fluids under downhole conditions of composition, pressure and temperature typically are different from the fluids at surface conditions. For example, downhole temperatures in a well could range from 300° F. When samples of downhole fluids are transported to the surface, change in temperature of the fluids tends to occur, with attendant changes in volume and pressure. The changes in the fluids as a result of transportation to the surface cause phase separation between gaseous and liquid phases in the samples, and changes in compositional characteristics of the formation fluids.
Techniques also are known to maintain pressure and temperature of samples extracted from a well so as to obtain samples at the surface that are representative of downhole formation fluids. In conventional systems, samples taken downhole are stored in a special chamber of the formation tester tool, and the samples are transported to the surface for laboratory analysis. During sample transfer from below surface to a surface laboratory, samples often are conveyed from one sample bottle or container to another bottle or container, such as a transportation tank. In this, samples may be damaged during the transfer from one vessel to another.
Furthermore, sample pressure and temperature frequently change during conveyance of the samples from a wellsite to a remote laboratory despite the techniques used for maintaining the samples at downhole conditions. The sample transfer and transportation procedures currently in use are known to damage or spoil formation fluid samples by bubble formation, solid precipitation in the sample, among other difficulties associated with the handling of formation fluids for surface analysis of downhole fluid characteristics.
In addition, laboratory analysis at a remote site is time consuming. Delivery of sample analysis data takes anywhere from a couple of weeks to months for a comprehensive sample analysis. This hinders the ability to satisfy users' demand for real-time results and answers (i.e., answer products). Typically, the time frame for answer products relating to surface analysis of formation fluids is a few months after a sample has been sent to a remote laboratory.
As a consequence of the shortcomings in surface analysis of formation fluids, recent developments in downhole fluid analysis include techniques for characterizing formation fluids downhole in a wellbore or borehole. In this, the MDT may include one or more fluid analysis modules, such as the composition fluid analyzer (CFA) and live fluid analyzer (LFA) of Schlumberger, for example, to analyze downhole fluids sampled by the tool while the fluids are still located downhole.
In downhole fluid analysis modules of the type described above, formation fluids that are to be analyzed downhole flow past a sensor module associated with the fluid analysis module, such as a spectrometer module, which analyzes the flowing fluids by infrared absorption spectroscopy, for example. In this, an optical fluid analyzer (OFA), which may be located in the fluid analysis module, may identify fluids in the flow stream and quantify the oil and water content. U.S. Pat. No. 4,994,671 (incorporated herein by reference in its entirety) describes a borehole apparatus having a testing chamber, a light source, a spectral detector, a database, and a processor. Fluids drawn from the formation into the testing chamber are analyzed by directing the light at the fluids, detecting the spectrum of the transmitted and/or backscattered light, and processing the information (based on information in the database relating to different spectra), in order to characterize the formation fluids.
In addition, U.S. Pat. Nos. 5,167,149 and 5,201,220 (both incorporated herein by reference in their entirety) describe apparatus for estimating the quantity of gas present in a fluid stream. A prism is attached to a window in the fluid stream and light is directed through the prism to the window. Light reflected from the window/fluid flow interface at certain specific angles is detected and analyzed to indicate the presence of gas in the fluid flow.
As set forth in U.S. Pat. No. 5,266,800 (incorporated herein by reference in its entirety), monitoring optical absorption spectrum of fluid samples obtained over time may allow one to determine when formation fluids, rather than mud filtrates, are flowing into the fluid analysis module. Further, as described in U.S. Pat. No. 5,331,156 (incorporated herein by reference in its entirety), by making optical density (OD) measurements of the fluid stream at certain predetermined energies, oil and water fractions of a two-phase fluid stream may be quantified.
On the other hand, samples extracted from downhole are analyzed at a surface laboratory by utilizing a pressure and volume control unit (PVCU) that is operated at ambient temperature and heating the fluid samples to formation conditions. However, a PVCU that is able to operate with precision at high downhole temperature conditions is not currently available. Conventional apparatuses for changing the volume of fluid samples under downhole conditions use hydraulic pressure with one attendant shortcoming that it is difficult to precisely control the stroke and speed of the piston under the downhole conditions due to oil expansion and viscosity changes that are caused by the extreme downhole temperatures. Furthermore, oil leakages at O-ring seals are experienced under the high downhole pressures requiring excessive maintenance of the apparatus.
Conventionally, a linear stroke piston type pump has been used for the described application. However, this kind of pump has several disadvantages when used for the downhole fluids. The linear stroke piston pump is big and requires a very powerful motor with ball pumping screw and valves. The dead volume of the linear stroke piston type pump is very big, and it requires a dynamic pressure seal on the pistons. Further, the pump of this type contributes to volume changes in the pumped fluids. In addition, when this pump stops, the fluid is prevented from passing through. In other words, unless the pump functions, the fluid sample cannot be introduced into the looped flowline. Further, if the pump does not function, it takes a long time to change a first sample of a first measurement point to a second sample of another measurement point by purging the first sample out from the looped flowline. As a result, two samples are mixed, and measurement error may occur when the purging time is not sufficient.
Further, a gear pump may be used for the above application. However, the size of the gear pump is big, and the dead volume is also big because of the size of the gears. If a small amount of sand is present in the fluid, the sand sticks between the gears and damages them or stops their rotation. Similarly, to the linear stroke piston pump, the fluid cannot flow through the gear pump when it is not operational.
A PCP (progressive cavity pump) is also known in the art. This pump is used as a downhole production pump. This pump may not stick due to sand contamination. PCP is a robust and reliable pump in oil field operations that does not get clogged by sand. However, a PCP stator is made with elastic material (typically rubber). This is not suitable for use in quick pressure change circuits such as bubble point detectors. This has high reverse flow impedance. To get large flow rate, a large rotator is required.
FIG. 15 shows an example of the structure of a centrifuge magnetic coupling pump. The centrifuge magnetic coupling pump 300 includes a housing 301, an impeller 304, a shaft 306, an inside magnet 308, an outside magnet 310 and a motor 312. The housing 301 includes an inlet 302 from which fluids 314 are introduced and an outlet 303 from which the fluids 314 are discharged. The impeller 304, the shaft 306 and the inside magnet 308 are provided in the housing 301. The impeller 304 is provided at one end of the shaft 306 and the inside magnet 308 is provided around the shaft such that inside magnet 308 and the impeller 304 rotate with the shaft 306. The outside magnet 310 is provided outside the housing 301 to face the inside magnet 308. The outside magnet 310 is connected to the motor 312 to be rotated by the motor 312. When the outside magnet 310 is rotated by the motor 312, the inside magnet 308 follows the outside magnet 310 to rotate the shaft 306 and the impeller 304 therewith. With this function, the fluid 314 is introduced from the inlet 302 and discharged from the outlet 303. This pump has capability of large flow rate, but the pump itself requires dead fluid volume. Further, reverse flow impedance is dependent on the gap between the impeller 304 and the housing. The housing section around the impeller 304 has to have a much larger diameter than the intake line diameter because this pump uses centrifuge force. Therefore, housing thickness has to be increased. As described above, conventionally, there have been problems in finding a proper circulation pump to be used for circulating downhole fluids